1. Field of the Invention
The present invention relates generally to high speed digital data communications for use in downhole telemetry. More specifically, the invention relates to a high-speed communications scheme for transferring data between downhole sensors and surface computers. More specifically still, the invention relates to a downhole telemetry system having discrete multi-tone modulation and dynamic bandwidth allocation between uplink and downlink data streams.
2. Description of Related Art
Modem petroleum drilling and production operations demand a great quantity of information relating to parameters and conditions downhole. Such information typically includes characteristics of the earth formations traversed by the wellbore, along with data relating to the size and configuration of the borehole itself. The collection of information relating to conditions downhole, which commonly is referred to as xe2x80x9cloggingxe2x80x9d, can be performed by several methods.
In conventional oil well wireline logging, a probe or xe2x80x9csondexe2x80x9d housing formation sensors is lowered into the borehole after some or all of the well has been drilled, and is used to determine certain characteristics of the formations traversed by the borehole. The upper end of the sonde is attached to a conductive wireline that suspends the sonde in the borehole. Power is transmitted to the sensors and instrumentation in the sonde through the conductive wireline. Similarly, the instrumentation in the sonde communicates information to the surface by electrical signals transmitted through the wireline.
An alternative method of logging is the collection of data during the drilling process. Collecting and processing data during the drilling process eliminates the necessity of removing or tripping the drilling assembly to insert a wireline logging tool. It consequently allows the driller to make accurate modifications or corrections as needed to optimize performance while minimizing down time. Designs for measuring conditions downhole including the movement and location of the drilling assembly contemporaneously with the drilling of the well have come to be known as xe2x80x9cmeasurement-while-drillingxe2x80x9d techniques, or xe2x80x9cMWDxe2x80x9d. Similar techniques, concentrating more on the measurement of formation parameters, commonly have been referred to as xe2x80x9clogging while drillingxe2x80x9d techniques, or xe2x80x9cLWDxe2x80x9d. While distinctions between MWD and LWD may exist, the terms MWD and LWD often are used interchangeably. For the purposes of this disclosure, the term MWD will be used with the understanding that this term encompasses both the collection of formation parameters and the collection of information relating to the movement and position of the drilling assembly.
Sensors or transducers typically are located at the lower end of the drill string in LWD systems. While drilling is in progress these sensors continuously or intermittently monitor predetermined drilling parameters and formation data and transmit the information to a surface detector by some form of telemetry. Typically, the downhole sensors employed in MWD applications are positioned in a cylindrical drill collar that is positioned close to the drill bit. The MWD system then employs a system of telemetry in which the data acquired by the sensors is transmitted to a receiver located on the surface. There are a number of telemetry systems in the prior art which seek to transmit information regarding downhole parameters up to the surface without requiring the use of a wireline. Of these, the mud pulse system is one of the most widely used telemetry systems for MWD applications.
The mud pulse system of telemetry creates xe2x80x9cacousticxe2x80x9d pressure signals in the drilling fluid that is circulated under pressure through the drill string during drilling operations. The information that is acquired by the downhole sensors is transmitted by suitably timing the formation of pressure pulses in the mud stream. The information is received and decoded by a pressure transducer and computer at the surface.
In a mud pressure pulse system, the drilling mud pressure in the drill string is modulated by means of a valve and control mechanism, generally termed a pulser or mud pulser. The pulser is usually mounted in a specially adapted drill collar positioned above the drill bit. The generated pressure pulse travels up the mud column inside the drill string at the velocity of sound in the mud. Depending on the type of drilling fluid used, the velocity may vary between approximately 3000 and 5000 feet per second. The rate of transmission of data, however, is relatively slow due to pulse spreading, distortion, attenuation, modulation rate limitations, and other disruptive forces, such as the ambient noise in the drill string. A typical pulse rate is on the order of a pulse per second (1 Hz).
Yet another method of gathering downhole data is seismic imaging. Classic seismic imaging involves stringing hundreds of listening devices, or geophones, over the surface of the Earth near a location where a characteristic picture of the underground formations is desired. Geophones measure both compressional and shear waves directly and they include particle velocity detectors. Geophones typically provide three-component velocity measurement. Geophones can be used to determine the direction of arrival of incident elastic waves. Once these geophones are strategically placed on the surface of the Earth, a seismic disturbance is created which creates traveling waves through the Earth""s crust. As these traveling waves encounter boundaries of strata having varying densities, portions of the traveling wave reflect back to the surface. These varying density stratas may include changes in strata components as well as varying densities encountered at boundaries of hydrocarbon reservoirs. By measuring the propagation time, amplitude and direction of reflected waves as they reach the surface, a three-dimensional representation of the formations lying below the surface of the Earth can be constructed.
After a particular hydrocarbon formation is found, the need for information is not alleviated. Once a hydrocarbon reservoir is tapped, the goal becomes removing as much of the hydrocarbons from the reservoir as possible. Here again, the more information one has about the locations of hydrocarbons within the reservoir over the course of time, the more likely the hydrocarbons contained in the reservoir can be fully extracted at the lowest possible cost. Having multiple three-dimensional seismic representations of conditions below the surface over time is typically referred to as four-dimensional (4D) seismic imaging. In early implementations, four-dimensional seismic was created by performing multiple three-dimensional seismic images of the strata or hydrocarbon reservoir in question. However, obtaining four-dimensional seismic representations of underground hydrocarbon reservoirs in this manner has its problems. For instance, the time period for taking readings to determine migration patterns of the hydrocarbons may be as long as years. That is, a single three-dimensional seismic reading may be taken once a year over the course of several years to obtain the four-dimensional seismic image. Each time this three-dimensional seismic image is taken, miles of cables containing geophones must be laid on the surface of the Earth. It is almost impossible to lay these cables in exactly the same location between each three-dimensional imaging session and further, even if the cables are placed relatively close to their locations from previous measurements, the geophones within the cable themselves may not be physically located the same as in previous three-dimensional images.
One way to combat these problems is to place the geophones vertically instead of horizontally. Rather than stretching cables across the surface of the Earth to place the geophones in a relatively horizontal position, the geophones themselves are semi-permanently lowered into well bores such that they are oriented vertically with respect to the surface of the Earth. The well bore into which the geophones may be lowered could be, for example, an existing oil or gas well or may be a well bore dedicated to sensor installation. While permanent placement of the geophones in a well bore may solved the placement problem for four-dimensional seismic imaging, new problems arise.
Given that seismic imaging fundamentally is measuring the arrival time of reflected waves at one location relative to arrival of reflected waves at another location, knowing the arrival time of all reflected waves relative to each other is critical to the computationally heavy burden of reconstructing an image of the below ground structures over time. To accomplish this task, large quantities of information must be recorded, substantially simultaneously, to correlate the arrival time of the various reflected waves. For traditional 3D seismic operations, whose sensors are simply laid on the surface of the Earth, having sufficient physical space necessary to communicate with each geophone is not a concern. For example, each geophone may have a single twisted pair cable, dedicated just to that geophone, coupled to a computer such that the computer can read each geophone substantially simultaneously. However, when permanently installing geophones in a vertical orientation in a well bore, physical space is not in abundance and therefore having a dedicated twisted pair cable for each geophone may not be feasible. Indeed, having a cable with a dedicated twisted pair for each geophone in a vertically oriented system, which may have as many as two hundred geophones, may require more cable cross-sectional area than the borehole itself.
Information is the key to being profitable in the oil and gas industry. The more information one has regarding location and migration patterns of hydrocarbons within a hydrocarbon reservoir, the more likely it is that that reservoir can be tapped at its optimal location and utilized to its full potential. To this end, new and moresophisticated sensor arrangements are routinely created and placed in the wireline sonde, so much so that the information carrying capacity of traditional wireline telemetry techniques are becoming inadequate. For these reasons it would be desirable to have a communication technique that can support high speed communications between downhole sensors and a surface installation.
The problems noted above are solved in large part by a downhole telemetry system having discrete multi-tone modulation and dynamic bandwidth allocation. In one embodiment, the downhole telemetry system comprises a surface transceiver, a cable, and a downhole transceiver coupled to the surface transceiver via the cable. The downhole transceiver communicates to the surface transceiver using discrete multi-tone (DMT) modulation to transmit telemetry information over a set of frequency subchannels allocated for uplink communications. The surface transceiver may likewise communicate to the downhole transceiver using DMT modulation to transmit information over a set of frequency subchannels allocated for downlink communications. The number of uplink and downlink communications subchannels is preferably variable and preferably can be changed depending on the operating mode of the system. This allows additional subchannels to be allocated for downlink communications during programming and configuration of the downhole equipment, and additional subchannels to be allocated for uplink communications during normal logging operations. The set of uplink communications subchannels may be disjoint from the set of downlink communications subchannels, and the sets may be spaced apart in frequency or interleaved in frequency. The cable may be a single conductor or multi-conductor logging cable. In the case of the multi-conductor logging cable, one of several possible orthogonal transmission modes may be used to convey the information signals.